Use of alternate refrigerants in optimized cascade process

ABSTRACT

Methods and systems for liquefying natural gas using nonflammable refrigerants are provided. Methods of liquefaction include cooling a natural gas stream via indirect heat exchange with a first nonflammable refrigerant selected from the group consisting of: difluoromethane, pentafluoromethane, trifluoromethane, hexafluoroethane, tetrafluoroethane, pentafluorethane, trifluoroethane, pentafluoroethane, any derivative thereof, and any combination thereof during a first refrigeration cycle; and cooling the natural gas stream via indirect heat exchange with a second refrigerant during a second refrigeration cycle.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a non-provisional application which claims benefitunder 35 USC §119(e) to U.S. Provisional Application Ser. No. 61/733,304filed Dec. 4, 2012, entitled “USE OF ALTERNATE REFRIGERANTS IN OPTIMIZEDCASCADE PROCESS,” which is incorporated herein in its entirety.

FIELD OF THE INVENTION

The present invention relates generally to methods for liquefyingnatural gas. More particularly, but not by way of limitation,embodiments of the present invention include methods and systems forliquefying natural gas using nonflammable refrigerants.

BACKGROUND OF THE INVENTION

Natural gas is an important resource widely used as energy source or asindustrial feedstock used in, for example, manufacture of plastics.Comprising primarily of methane, natural gas is a mixture of naturallyoccurring hydrocarbon gases and is typically found in deep undergroundnatural rock formations or other hydrocarbon reservoirs. Othercomponents of natural gas may include, but are not limited to, ethane,propane, carbon dioxide, nitrogen, and hydrogen sulfide. Typically,natural gas is transported from source to consumers through pipelinesthat physically connect reservoir to market.

Because natural gas is sometimes found in remote areas devoid of certaininfrastructure (e.g., pipelines), alternative methods for transportingnatural gas must be used. This situation commonly arises when the sourceof natural gas and the market are separated by great distances, forexample, a large body of water. Bringing this natural gas from remoteareas to market can have significant commercial value if the cost oftransporting natural gas is minimized.

One alternative method of transporting natural gas involves convertingnatural gas into a liquefied form via liquefaction process. Becausenatural gas is gaseous under standard atmospheric conditions, it istypically subjected to thermodynamic processes in order to be liquefied.In its liquefied form, natural gas has a specific volume that issignificantly lower than its specific volume in its gaseous form. Thus,the liquefaction process greatly increases the ease of transporting andstoring natural gas, particularly in cases where pipelines are notavailable. For example, ocean liners carrying liquefied natural gastanks can effectively link a natural gas source to a distant market whenseparated by an ocean.

Converting natural gas to its liquefied form can have other economicbenefits as well. For example, storing liquefied natural gas (LNG) canhelp balance out periodic fluctuations in natural gas supply and demand.In particular, LNG can be more easily “stockpiled” for later use whennatural gas demand is low and/or supply is high. As a result, futuredemand peaks can be met with LNG from storage, which can be vaporized asdemand requires.

At least several conventional methods exist for liquefying natural gas.In one method, a propane pre-cooled mixed refrigerant is used to coolnatural gas. The mixed refrigerant typically includes, but is notlimited to, nitrogen, methane, ethane, and propane. In another method(e.g., optimized cascade process), natural gas is converted into LNG byutilizing multiple refrigerants in one or more mechanical refrigerationcycles that are used to lower the temperature of a natural gas stream.During the optimized cascade process, natural gas is first treated toremove contaminants including, but not limited to, CO₂, water, andmercury before entering the liquefaction section of an LNG plant. Thetreated gas is then chilled to approximately −260° F. in successivelycolder heat exchangers that use propane, ethylene, and methane asrefrigerants. In some cases, the refrigerants are pure or substantiallypure substances. In other cases, the refrigerants can be mixturescomprising more than one component. The product leaving the methaneexchangers is LNG that is ready for storage. The LNG product is thenpumped into insulated storage tanks before being loaded on special shipsto be transported to LNG import terminals around the world.

While LNG and LNG facilities are generally considered safe there arecertain inherent safety risks associated with hydrocarbon processingtechniques. For example, conventional LNG refrigerants such as propaneand ethylene are flammable materials. One potential catastrophic outcomearising from an accidental release of flammable materials is a vaporcloud explosion. Vapor cloud explosion can start the released flammablematerial forms a vapor cloud within a congested or confined area.Ignition of this cloud produces a flame front that accelerates throughthe congestion and creates a pressure wave. The severity of the pressurewave depends on several factors including, but not limited to, type offuel released, size of the cloud within the congested/confined area, anddegree of congestion/confinement within the cloud. As processing plantsbecome more congested and confined, risk of explosion can increase. Mostvapor cloud explosions have subsonic flame speeds and are classified asdeflagrations. Even short-duration deflagrations can result insignificant damage to buildings, equipments, and people. Potentialdamage is primarily a function of total amount of fuel burned, themaximum flame velocity that is achieved, and the manner in which theexpansion of the combustion gases is contained.

Typically, LNG facilities are built in sufficiently open spaces in orderto reduce the chances of a vapor cloud explosion in the unlikely casethat flammable material is released. Other design considerations canalso reduce the risk of explosion.

Moreover, recent expansion of LNG technology for offshore developmentshave prompted new studies analyzing safety risks of offshore LNGfacilities. While these studies generally demonstrate that offshore LNGtechnology does not present unsafe risk levels, additional riskreduction efforts should always be considered.

BRIEF SUMMARY OF THE DISCLOSURE

The present invention relates generally to methods for liquefyingnatural gas. More particularly, but not by way of limitation,embodiments of the present invention include methods and systems forliquefying natural gas using nonflammable refrigerants.

One example of a method for liquefaction of natural gas comprises thesteps of: a) cooling a natural gas stream via indirect heat exchangewith a first nonflammable refrigerant selected from the group consistingof: difluoromethane, pentafluoromethane, trifluoromethane,hexafluoroethane, tetrafluoroethane, pentafluorethane, trifluoroethane,pentafluoroethane, any derivative thereof, and any combination thereofduring a first refrigeration cycle; and b) cooling the natural gasstream via indirect heat exchange with a second refrigerant during asecond refrigeration cycle.

Another example of a method for liquefaction of natural gas comprisesthe steps of: a) providing at least one nonflammable refrigerantselected from the group consisting of: difluoromethane,pentafluoroethane, trifluoromethane, hexafluoroethane,tetrafluoroethane, pentafluorethane, trifluoroethane, pentafluoroethane,any derivative thereof, and any combination thereof; and b) cooling anatural gas stream in an LNG facility via indirect heat exchange withthe nonflammable refrigerant.

Yet another example of a method for liquefaction of natural gascomprises the steps of: a) cooling a natural gas stream in a LNGfacility via indirect heat exchange with a first nonflammablerefrigerant selected from the group consisting of: difluoromethane,pentafluoroethane, trifluoromethane, hexafluoroethane,tetrafluoroethane, pentafluorethane, trifluoroethane, pentafluoroethane,any derivative thereof, and any combination thereof during a firstrefrigeration cycle; b) cooling the natural gas stream in the LNGfacility via indirect heat exchange with a second refrigerant during asecond refrigeration cycle; and c) cooling the natural gas stream in theLNG facility via indirect heat exchange with a third refrigerant duringthe third refrigeration cycle.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present disclosure and advantagesthereof may be acquired by referring to the follow description taken inconjunction with the accompanying figures, wherein:

FIG. 1 is a plot summarizing effects of nonflammable refrigerants onlaminar burning velocity as described in Example 1.

FIG. 2 is a plot summarizing effects of nonflammable refrigerants onlaminar burning velocity as described in Example 1.

While the present invention is susceptible to various modifications andalternative forms, specific exemplary embodiments thereof have beenshown by way of example in the drawings and are herein described indetail. It should be understood, however, that the description herein ofspecific embodiments is not intended to limit the invention to theparticular forms disclosed, but on the contrary, the intention is tocover all modifications, equivalents, and alternatives falling withinthe spirit and scope of the invention as defined by the appended claims.

DETAILED DESCRIPTION

The present invention relates generally to methods for liquefyingnatural gas. More particularly, but not by way of limitation,embodiments of the present invention include methods and systems forliquefying natural gas using nonflammable refrigerants.

There are certain inherent safety risks related to transporting andprocessing of LNG. These include, but are not limited to, hydrocarbonand LNG process and tanks, helicopter transportation, occupational, andship collision. Certain risk evaluations indicate the general riskperspective that hydrocarbon (including LNG) processing and tanks cancontribute to ˜25-50% of the overall risk to personnel engaged in alarge LNG operation. As most refrigerants used in large LNG operationsare flammable, they can contribute to the overall safety risk topersonnel. It is believed that the portion of risk attributed toflammable refrigerants can be on the order of 2-5%. In addition to thepersonnel risk, potential impacts of an explosion (e.g., vapor cloudexplosion) arising from the use of flammable refrigerants include damageand/or loss of facility assets and major business interruption. Whilecurrent use of flammable refrigerants are generally considered safe inthe context of overall risk, there may be safer alternative refrigerantsthat can reduce inherent risks to personnel.

Various parameters can lessen or heighten the risk of a vapor cloudexplosion. Some of the parameters affecting the risk of vapor cloudexplosions include, but are not limited to, degree of congestion, degreeof confinement, gas cloud size gas concentration, gas type (reactivity),ignition location, active mitigation measures, and the like. The risk ofvapor cloud explosion may be lowered by addressing any one (e.g., gastype reactivity) or more of the parameters. Conventional refrigerantsused during LNG process such as methane have relatively low reactivitywhile other conventional refrigerants have high reactivity (e.g.,ethylene) or medium reactivity (e.g., propane). Fuels are typicallyconsidered low reactivity if their laminar burning velocities (LBVs) arelower than about 40 cm/s. Medium reactivity fuels typically have LBVsbetween about 40 to about 75 cm/s. High reactivity fuels have LBVs ofgreater than about 75 cm/s. In general, reactivity increases as LBVincreases. Thus, lowering the reactivity of refrigerants used during LNGprocesses can lower the risk of vapor cloud explosion as well as theoverall safety risk basis arising from LNG facilities and relatedactivities.

Some of the approaches for reducing safety risks associated with LNGprocesses involve increasing equipment spacing or designing safetysystems to mitigate fire and explosion risks. To date the use ofnonflammable refrigerants, particularly in certain LNG processes (e.g.,cascade LNG processes, floating LNG facilities, etc.) have beennon-existent or limited. Alternative approaches involving nonflammablerefrigerants are often limited by technical challenges. The physicalproperties of many nonflammable refrigerants differ from conventionalLNG refrigerants (i.e., propane, ethylene, etc.) such that significantmodifications to the design of LNG facilities may be required in orderto achieve desirable operating efficiency. For example, use ofnonflammable refrigerants may require higher operating pressures on theheavies removal unit. Other design modifications may involve addressingone or more of the following: possible combination of nonflammablerefrigerant with physical solvent removal in upstream units; possiblecombination of nonflammable refrigerant with combustible refrigerants;novel compressor driver arrangement and higher methane compressordischarge pressures; and the like. There may also be considerabletechnical challenges in scaling the use of nonflammable refrigerants inLNG processes.

Reference will now be made in detail to embodiments of the invention,one or more examples of which are illustrated in the accompanyingdrawings. Each example is provided by way of explanation of theinvention, not as a limitation of the invention. It will be apparent tothose skilled in the art that various modifications and variations canbe made in the present invention without departing from the scope orspirit of the invention. For instance, features illustrated or describedas part of one embodiment can be used on another embodiment to yield astill further embodiment. Thus, it is intended that the presentinvention cover such modifications and variations that come within thescope of the invention.

The present invention provides compositions and methods related tolowering safety risk associated with LNG facilities and associatedactivities. In certain embodiments, a nonflammable refrigerant that iscompatible with LNG processes is provided. The nonflammable refrigerantmay be used in place of conventional LNG refrigerants (e.g., methane,propane, ethylene, etc.) or may be used in conjunction with conventionalLNG refrigerants to form a refrigerant mixture. Other additives may beadded to the refrigerant or refrigerant mixture as desired.

As compared to many conventional methods, advantages of certainembodiments of liquefying natural gas methods and systems describedherein include, but are not limited to, one or more of the following:

-   -   lower safety risks of significant fires and explosions,    -   elimination of certain safety equipments,    -   reduced spacing requirements,    -   significant reduction in capital expenditure,    -   well-suited for offshore or near populated areas where space is        limited.        Other advantages will be apparent from the disclosure herein.

Cascade LNG

The present invention can be implemented in a process/facility used tocool natural gas to its liquefaction temperature, thereby producing LNG.The LNG process generally employs one or more refrigerants to extractheat from the natural gas and then reject the heat to the environment.Certain LNG processes may comprise multiple refrigerants. For example, afirst refrigerant may be used to cool a first refrigeration cycle. Asecond refrigerant may be used to cool a second refrigeration cycle. Athird refrigerant may be used to cool a third refrigeration cycle. Asused herein, the terms “first”, “second”, and “third” refer to therelative position of the cycle with respect to each other. For example,the first refrigeration cycle is positioned just upstream of the secondrefrigeration cycle while the second refrigeration cycle is positionedupstream of the third refrigeration cycle and so forth. An optimizedcascade LNG process typically utilizes propane, ethylene, and methane asthe first, second, and third refrigerant respectively.

In one embodiment, the LNG process in accordance with one or moreembodiments of the present invention employs a cascade-typerefrigeration process that uses a plurality of multi-stage coolingcycles, each employing a different refrigerant composition, tosequentially cool the natural gas stream to lower and lowertemperatures. In another embodiment, the LNG process is a mixedrefrigerant process that employs a combination of two or morerefrigerants to cool the natural gas stream in at least one coolingcycle.

Natural gas can be delivered to the LNG process at an elevated pressurein the range of from about 500 to about 3,000 pounds per square inabsolute (psia), about 500 to about 1,000 psia, or 600 to 800 psia.Depending largely upon the ambient temperature, the temperature of thenatural gas delivered to the LNG process can generally be in the rangeof from about 0 to about 180° F. (about −18 to about 82° C.), or about20 to about 150° F. (about −7 to about 66° C.), or 60 to 125° F. (about16 to about 52° C.

While reference to a specific cascade LNG process comprising 3refrigeration cycles involving 3 refrigerants is made, this is notintended to be limiting. It is recognized that a cascade LNG processinvolving more or less refrigerants and/or refrigeration cycles may becontemplated. Other variations to the cascade LNG process as well asalternative compatible LNG processes may also be contemplated.

In one embodiment, the present invention can be implemented in an LNGprocess that employs cascade-type cooling followed by expansion-typecooling. In such a liquefaction process, the cascade-type cooling may becarried out in a mechanical refrigeration cycle at an elevated pressure(e.g., about 650 psia) by sequentially passing the natural gas streamthrough first, second, and third refrigeration cycles employingrespective first, second, and third refrigerants. In one embodiment, thefirst and second refrigeration cycles are closed refrigeration cycles,while the third refrigeration cycle is an open refrigeration cycle thatutilizes a portion of the processed natural gas as a source of therefrigerant. Further, the third refrigeration cycle can include amulti-stage expansion cycle to provide additional cooling of theprocessed natural gas stream and reduce its pressure to near atmosphericpressure.

In the sequence of first, second, and third refrigeration cycles, therefrigerant having the highest boiling point can be utilized first,followed by a refrigerant having an intermediate boiling point, andfinally by a refrigerant having the lowest boiling point. In oneembodiment, the refrigerant can be a hydrocarbon-containing refrigerant.In another embodiment, the first refrigerant has a mid-boiling point atstandard temperature and pressure (i.e., an STP mid-boiling point)within about 20, about 10, or 5° F. of the STP boiling point of purepropane. The first refrigerant can contain predominately propane,propylene, or mixtures thereof. The first refrigerant can contain atleast about 75 mole percent propane, at least 90 mole percent propane,or can consist essentially of propane. In one embodiment, the secondrefrigerant has an STP mid-boiling point within about 20, about 10, or5° F. of the STP boiling point of pure ethylene. The second refrigerantcan contain predominately ethane, ethylene, or mixtures thereof. Thesecond refrigerant can contain at least about 75 mole percent ethylene,at least 90 mole percent ethylene, or can consist essentially ofethylene. In one embodiment, the third refrigerant has an STPmid-boiling point within about 20, about 10, or 5° F. of the STP boilingpoint of pure methane. The third refrigerant can contain at least about50 mole percent methane, at least about 75 mole percent methane, atleast 90 mole percent methane, or can consist essentially of methane. Atleast about 50, about 75, or 95 mole percent of the third refrigerantcan originate from the processed natural gas stream.

The first refrigeration cycle can cool the natural gas in a plurality ofcooling stages/steps (e.g., two to four cooling stages) by indirect heatexchange with the first refrigerant. Each indirect cooling stage of therefrigeration cycles can be carried out in a separate heat exchanger. Inthe one embodiment, core-and-kettle heat exchangers are employed tofacilitate indirect heat exchange in the first refrigeration cycle.After being cooled in the first refrigeration cycle, the temperature ofthe natural gas can be in the range of from about −45 to about −10° F.(about −43 to about −23° C.), or about −40 to about −15° F. (about −40to about −26° C.), or about −20 to −30° F. (−29 to about −34° C.). Atypical decrease in the natural gas temperature across the firstrefrigeration cycle may be in the range of from about 50 to about 210°F. (about 10 to about 99° C.), about 75 to about 180° F. (about 24 toabout 82° C.), or about 100 to about 140° F. (about 38 to about 60° C.).

The second refrigeration cycle can cool the natural gas in a pluralityof cooling stages/steps (e.g., two to four cooling stages) by indirectheat exchange with the second refrigerant. In one embodiment, theindirect heat exchange cooling stages in the second refrigeration cyclecan employ separate, core-and-kettle heat exchangers. Generally, thetemperature drop across the second refrigeration cycle can be in therange of from about 50 to about 180° F. (about 10 to about 82° C.),about 75 to about 150° F. (about 24 to about 66° C.), or about 100 toabout 120° F. (about 38 to about 49° C.). In the final stage of thesecond refrigeration cycle, the processed natural gas stream can becondensed (i.e., liquefied) in major portion, preferably in itsentirety, thereby producing a pressurized LNG-bearing stream. Generally,the process pressure at this location is only slightly lower than thepressure of the natural gas fed to the first stage of the firstrefrigeration cycle. After being cooled in the second refrigerationcycle, the temperature of the natural gas may be in the range of fromabout −205 to about −70° F. (about −132 to about −57° C.), about −175 toabout −95° F. (about −115 to about −71° C.), or about −140 to about−125° F. (about −96 to about −87° C.).

The third refrigeration cycle can include both an indirect coolingsection and an expansion-type cooling section. To facilitate indirectheat exchange, the third refrigeration cycle can employ at least onebrazed-aluminum plate-fin heat exchanger. The total amount of coolingprovided by indirect heat exchange in the third refrigeration cycle canbe in the range of from about 5 to about 60° F., about 7 to about 50°F., or 10 to 40° F.

The expansion-type cooling section of the third refrigeration cycle canfurther cool the pressurized LNG-bearing stream via sequential pressurereduction to approximately atmospheric pressure. Such expansion-typecooling can be accomplished by flashing the LNG-bearing stream tothereby produce a two-phase vapor-liquid stream. When the thirdrefrigeration cycle is an open refrigeration cycle, the expandedtwo-phase stream can be subjected to vapor-liquid separation and atleast a portion of the separated vapor phase (i.e., the flash gas) canbe employed as the third refrigerant to help cool the processed naturalgas stream. The expansion of the pressurized LNG-bearing stream to nearatmospheric pressure can be accomplished by using a plurality ofexpansion steps (i.e., two to four expansion steps) where each expansionstep is carried out using an expander. Suitable expanders include, forexample, either Joule-Thomson expansion valves or hydraulic expanders.In one embodiment, the third stage refrigeration cycle can employ threesequential expansion cooling steps, wherein each expansion step can befollowed by a separation of the gas-liquid product. Each expansion-typecooling step can further cool the LNG-bearing stream in the range offrom about 10 to about 60° F., about 15 to about 50° F., or 25 to 35° F.The reduction in pressure across the first expansion step can be in therange of from about 80 to about 300 psia, about 130 to about 250 psia,or 175 to 195 psia. The pressure drop across the second expansion stepcan be in the range of from about 20 to about 110 psia, about 40 toabout 90 psia, or 55 to 70 psia. The third expansion step can furtherreduce the pressure of the LNG-bearing stream by an amount in the rangeof from about 5 to about 50 psia, about 10 to about 40 psia, or 15 to 30psia. The liquid fraction resulting from the final expansion stage is anLNG product. Generally, the temperature of the LNG product can be in therange of from about −200 to about −300° F. (−129 to about −184° C.),about −225 to about −275° F. (about −143 to about −170° C.), or about−240 to about −260° F. (about −151 to about −162° C.). The pressure ofthe LNG product can be in the range of from about 0 to about 40 psia,about 10 to about 20 psia, or 12.5 to 17.5 psia.

The natural gas feed stream to the LNG process will usually contain suchquantities of C2+ components so as to result in the formation of a C2+rich liquid in one or more of the cooling stages of the secondrefrigeration cycle. Generally, the sequential cooling of the naturalgas in each cooling stage is controlled so as to remove as much of theC2 and higher molecular weight hydrocarbons as possible from the gas,thereby producing a vapor stream predominating in methane and a liquidstream containing significant amounts of ethane and heavier components.This liquid can be further processed via gas-liquid separators employedat strategic locations downstream of the cooling stages. In oneembodiment, one objective of the gas/liquid separators is to maximizethe rejection of the C5+ material to avoid freezing in downstreamprocessing equipment. The gas/liquid separators may also be utilized tovary the amount of C2 through C4 components that remain in the naturalgas product to affect certain characteristics of the finished LNGproduct.

The exact configuration and operation of gas-liquid separators may bedependant on a number of parameters, such as the C2+ composition of thenatural gas feed stream, the desired BTU content of the LNG product, thevalue of the C2+ components for other applications, and other factorsroutinely considered by those skilled in the art of LNG plant and gasplant operation. In one embodiment of the present invention, the C2+hydrocarbon stream or streams may be demethanized via a single stageflash or a fractionation column. The gaseous methane-rich stream can bedirectly returned at pressure to the liquefaction process. The resultingheavies-rich liquid stream may then be subjected to fractionation in oneor more fractionation zones to produce individual streams rich inspecific chemical constituents (e.g., C2, C3, C4, and C5+).

The nonflammable refrigerants of the present invention may be usedduring liquefaction of natural gas. Refrigerants utilized incascade-type refrigeration processes can have successively lower boilingpoints in order to maximize heat removal from the natural gas streambeing liquefied. Additionally, cascade-type refrigeration processes caninclude some level of heat integration. For example, a cascade-typerefrigeration process can cool one or more refrigerants having a highervolatility via indirect heat exchange with one or more refrigerantshaving a lower volatility. In addition to cooling the natural gas streamvia indirect heat exchange with one or more refrigerants, cascade andmixed-refrigerant LNG systems can employ one or more expansion coolingstages to simultaneously cool the LNG while reducing its pressure tonear atmospheric pressure. In some embodiments, the nonflammablerefrigerant may be used in a floating LNG (FLNG) process. In one or moreembodiments, the nonflammable refrigerant may be used in an optimizedcascade LNG process.

Refrigerants

A refrigerant is a substance used in a heat cycle, which can undergo areversible phase transition from a liquid to a gas during an LNGprocess. A nonflammable refrigerant according to one or more embodimentsgenerally comprises simple fluorohydrocarbons that are nonflamamble. Insome embodiments, the nonflammable refrigerant may include, but notlimited to, one or more of the following: difluoromethane (sometimesreferred to as “R-32”), pentafluoroethane (sometimes referred to as“R-125” or “FE-25”), trifluoromethane (sometimes referred to as “R-23”or “FE-13”), hexafluoroethane (sometimes referred to as “R-116”),derivatives thereof, and mixtures thereof. Other suitable examples offluorohydrocarbons may include, but are not limited to, difluoropropane,trifluoropropane, tetrafluoropropane, pentafluoropropane, and the like.The hydrocarbon portion of the fluorohydrocarbon may comprise one ormore carbons. In some embodiments, the fluorohydrocarbon may comprisebetween one carbon to about ten carbons. In those embodiments, thefluorohydrocarbon may comprise one or more fluorines.

In some embodiments, the nonflammable refrigerant may comprise a mixtureof difluoromethane and pentafluoroethane. A 1:1 mixture (by weight) ofdifluoromethane and pentafluoroethane is sometimes referred to as“R-410A” and has a boiling point of −55.3° F. (−48.5° C.). In anotherexample, the nonflammable refrigerant may comprise a mixture oftrifluoromethane and hexafluoroethane. A 46:54 mixture (by weight) oftrifluoromethane and hexafluoroethane is sometimes referred to as“R-508B” and has a boiling of −126.94° F. (−88.3° C.). In thoseembodiments comprising a mixture of nonflammable refrigerants, eachnonflammable refrigerant may be present in about 0.1% up to about 100%by weight. The specific amount of nonflammable refrigerant present inthe mixture may be modified by one of ordinary skill in the art asdesired. Such modifications may depend on a number of factors including,but not limited to, desired boiling point, cost, availability, anddesired maximum LBV to minimize or eliminate the possibility of ignitionand/or reduce the overpressure from an ignited vapor cloud. In one ormore embodiments, the nonflammable refrigerant may comprise at least oneselected from the group consisting of: R-410A, R-508B, R-23, R-125, andany combination thereof. In some embodiments, the nonflammablerefrigerant may be an azeotropic mixture. In other embodiments, thenonflammable refrigerant may be a zeotropic mixture or near-azeotropicmixture.

In some embodiments, the nonflammable refrigerant is substantially freeof hydrocarbons. In other embodiments, the nonflammable refrigerantincludes a hydrocarbon component in an amount ranging from about 0.1% toabout 99.9% by volume or about 0.1% to about 99.9% by volume. In suchembodiments, the hydrocarbon may be selected from the group consistingof: ethylene, propane, methane, and any combination thereof.

In accordance with one or more embodiments, a nonflammable refrigerantcomprising a mixture of difluoromethane and pentafluoroethane (e.g.,R-410A) may be used as the first refrigerant of an optimized cascade LNGprocess. In other embodiments, R-134a (1,1,1,2-tetrafluoroethane), R-125(pentafluoroethane), R-404a (a blend of 52 wt % trifluoroethane, 44 wt %R-125, and 4 wt % R-134a), or combinations thereof may be used as thefirst refrigerant. In accordance with one or more embodiments, anonflammable refrigerant comprising a mixture of trifluoromethane andhexafluoroethane (e.g., R-508B) may be used as the second refrigerant ofan optimized cascade LNG process. When a nonflammable refrigerant isused in place of a flammable refrigerant (e.g., ethylene, propane), thechance of fire and explosion in an LNG facility is reduced. In oneaspect, the chance of deflagration to detonation transition may bereduced at least in part due to the reduction in equipment spacing. Theuse of nonflammable refrigerants also allows greater flexibility indesign LNG processes. For example, personnel quarters of a floating LNGfacility may be located closer to a nonflammable refrigerant loop whichreduces plot spacing and allows the nonflammable refrigerant to be usedas a utility for other facility spaces. Moreover, mixtures ofdifluoromethane and pentafluoroethane (e.g., R-410A) condense at a lowertemperature than propane which reduces energy and capital requirementfor the LNG process.

In some embodiments, difluoromethane, pentafluoroethane, or both may beadded to a flammable refrigerant (e.g., propane) as an additive that canreduce the flame speed of the flammable refrigerant. In someembodiments, the flame speed may be reduced below deflagration todetonation transition. In some embodiments, the flame speed may bereduce to less than or about the flame speed of methane (see Example 2).

The use of trifluoromethane and hexafluoroethane and other nonflammablerefrigerants may require modifications to conventional optimized cascadeLNG processes. For example, such use may require increased pressure inheavies removal column which causes the column to operate in retrogradecondensation region. Furthermore, this increased pressure may require,for example, a booster motor for methane compression system or otherrearrangement of gas turbine generator drivers. Methane compressordischarge pressures are typically limited to a value lower than thatrequired for the use of trifluoromethane and hexafluoromethane. Thus, itmay be desirable to use a physical solvent and include the heaviesremoval column upstream. Moreover, since the mixture of trifluoromethaneand hexafluoromethane condenses at a lower pressure than ethylene, areduced driving force will reduce refrigerant loss through compressorseals.

In some embodiments, at least one of trifluoromethane andhexafluoroethane may be added to a flammable refrigerant (e.g.,ethylene) as an additive which can reduce the flame speed of theflammable refrigerant. In some embodiments, the flame speed may bereduced below deflagration to detonation transition. In someembodiments, the flame speed may be reduce to less than or about theflame speed of methane (˜0.4 meters per second). The flame speed ofethylene is about 0.75 meters per second.

The following examples of certain embodiments of the invention aregiven. Each example is provided by way of explanation of the invention,one of many embodiments of the invention, and the following examplesshould not be read to limit, or define, the scope of the invention.

Example 1

In this Example, laminar burning velocities for various compounds weremeasured. The tests were performed using a constant-volume vessel inwhich gases were introduced using a partial pressure method, allowed tomix, and ignited. The resulting dynamic pressure trace was analyzed inorder to calculate the LBV.

The measured LBV values are summarized in Table 1 below. The reactivityof a compound increases as LBV increases. This reactivity is typically afunction of the strength of hydrogen bonding in the compound and not theheat of combustion or the thermal unit (e.g., BTU) value.

TABLE 1 Compound LBV (m/s) Methane ~0.40 Propane ~0.46 Ethylene ~0.75Acetylene ~1.55 Hydrogen ~3.25

FIG. 1 illustrates the results of an experiment in which variousnonflammable refrigerants and compounds such as hydrofluoro-olefin(HFO1234yf), R-410A, and CO₂ were added to propane. As the nonflammablerefrigerant fraction increases, the laminar burning velocity decreases.

FIG. 2 illustrates the results of an experiment in which variousnonflammable refrigerants (R-508B and R-23) were added to ethylene. Asthe nonflammable refrigerant fraction increases, the laminar burningvelocity decreases. FIGS. 1 and 2 illustrate that nonflammablerefrigerants may be added to flammable refrigerants to significantlyreduce laminar burning velocity of flammable refrigerants. Such plotsmay be used to determine mixtures having desired LBV values.

Example 2

Certain characteristics of an optimized cascade process improved whenR-410A was used as a nonflammable refrigerant in place of propane. Thesecharacteristics were simulated using REFPROP (version 8) in the AspenPhysical Property System and verified against National Institute ofStandards and Technology (NIST) tables. For example, the actual aircompressor capacity (ACFM) decreased by 10-30% which allows for asmaller compressor bundle. R-410A also provides a greater vapor density(69.4 kg/m³) as compared to propane (25.6 kg/m³) which permits highersystem mass flow and reduces pressure drop losses, allowing smallerdiameter piping and smaller equipment to obtain the same refrigerantduty achieved by propane. Table 2 below summarizes simulated propertiesof R410A using Aspen HYSYS®, a modeling software available throughAspentech Technology, Inc. (Burlington, Mass.). These results suggestthat R410A may be stable and behaves predictably throughout the giventemperature range.

TABLE 2 R410A modeling in HYSYS ® Phase Phase Phase Phase Phase PhaseMass Mass Mass Mass Mass Mass Entropy Phase Density Density EnthalpyEnthalpy Phase Entropy (Vapor change Vapor (Liquid (Vapor (Liquid (Vaporchange (Liquid Phase) delta S Temperature Pressure Phase) Phase) Phase)Phase) delta H Phase) [Btu/lb- (Btu/lb- [F.] [psia] [lb/ft3] [lb/ft3][Btu/lb] [Btu/lb] (Btu/lb) [Btu/lb-F.] F.] F.) −40 −0.94 −0.06 −0.480.00 0.00 0.00 0.00 −35 −0.64 −0.06 −0.41 1.02 −0.02 −0.04 0.92 0.000.00 −30 −0.60 −0.07 −0.33 1.02 −0.05 −0.08 1.03 −0.02 0.00 −25 −0.67−0.07 −0.26 0.99 −0.09 −0.14 0.99 −0.06 0.00 −20 −0.52 −0.06 −0.20 0.96−0.05 −0.11 0.98 −0.07 0.00 −15 −0.60 −0.07 −0.14 0.95 −0.11 −0.20 0.94−0.07 0.00 −10 −0.41 −0.06 −0.08 0.95 −0.10 −0.20 0.94 −0.09 0.00 −5−0.33 −0.07 −0.01 0.93 −0.10 −0.21 0.93 −0.13 0.00 0 −0.29 −0.07 0.010.93 −0.11 −0.24 0.89 −0.11 0.00 5 −0.26 −0.07 0.05 0.86 −0.13 −0.280.88 −0.12 0.00 10 −0.31 −0.08 0.16 0.87 −0.17 −0.34 0.88 −0.16 0.00 15−0.28 −0.07 0.14 0.84 −0.13 −0.32 0.87 −0.15 0.00 20 −0.16 −0.08 0.210.83 −0.20 −0.41 0.84 −0.17 0.00 25 −0.14 −0.08 0.26 0.84 −0.20 −0.430.84 −0.18 0.00 30 −0.18 −0.09 0.29 0.83 −0.21 −0.47 0.84 −0.22 0.00 35−0.14 −0.10 0.34 0.84 −0.16 −0.44 0.83 −0.21 −0.01 40 −0.11 −0.11 0.360.79 −0.22 −0.52 0.82 −0.24 −0.01 45 −0.06 −0.12 0.40 0.82 −0.21 −0.540.81 −0.23 −0.01 50 −0.04 −0.12 0.42 0.80 −0.22 −0.58 0.82 −0.26 −0.0155 −0.02 −0.14 0.43 0.82 −0.26 −0.66 0.81 −0.25 −0.01 60 0.01 −0.15 0.450.81 −0.24 −0.67 0.82 −0.28 −0.01 65 0.02 −0.17 0.49 0.81 −0.25 −0.710.82 −0.28 −0.01 70 0.03 −0.19 0.52 0.82 −0.29 −0.81 0.83 −0.32 −0.01 750.05 −0.22 0.53 0.83 −0.28 −0.84 0.82 −0.33 −0.01 80 0.05 −0.23 0.550.83 −0.30 −0.92 0.82 −0.35 −0.01 85 0.06 −0.25 0.55 0.83 −0.29 −0.940.83 −0.35 −0.01 90 0.04 −0.28 0.57 0.84 −0.31 −1.03 0.84 −0.36 −0.01 950.05 −0.33 0.60 0.84 −0.39 −1.22 0.83 −0.41 −0.01 100 0.08 −0.35 0.650.82 −0.36 −1.21 0.88 −0.43 −0.02 105 0.07 −0.38 0.67 0.84 −0.38 −1.330.85 −0.45 −0.02 110 0.07 −0.42 0.70 0.84 −0.47 −1.57 0.86 −0.50 −0.02115 0.06 −0.45 0.73 0.83 −0.47 −1.67 0.84 −0.51 −0.02 120 0.07 −0.500.78 0.83 −0.49 −1.82 0.80 −0.55 −0.02 125 0.07 −0.56 0.83 0.82 −0.53−2.02 0.85 −0.57 −0.02 130 0.06 −0.63 0.92 0.84 −0.63 −2.40 0.84 −0.59−0.03 135 0.06 −0.74 1.03 0.86 −0.65 −2.69 0.90 −0.67 −0.03 140 0.05−0.92 1.12 0.91 −0.73 −3.24 0.91 −0.69 −0.04

DEFINITIONS

As used herein, “confinement” and related terms refer to the presence ofobstructions that prevent flame propagation in any one of threedirections (x, y, or z directions). Objects may be confined in onedimension, two dimensions, or three dimensions.

As used herein, “congestion” and related terms refer to the presence ofobstacles that cause a flame front to flow around the obstacles thusgenerating turbulence and accelerating the flame front. Morespecifically, the terms “low congestion”, “medium congestion”, and “highcongestion” may be a context dependent term. For example, “lowcongestion” may be defined as having about 15% or less area blockageratio (ABR) and a pitch of greater than about 8D. In some embodiments,“low congestion” may refer to an area that is easy to walk throughrelatively unimpeded. The term “medium congestion” may refer to an areahaving between about 15% to about 30% ABR and a pitch of about 4D toabout 8D. In some embodiments, “medium congestion” may refer to an areathat can be walked through but requires taking an indirect path. Theterm “high congestion” may refer to an area having more than about 30%ABR and a pitch of less than about 4D. In some embodiments, “highcongestion” may refer to an area that cannot be walked through.

As used herein, the term “area blockage ratio” refers to the ratio ofthe volume of congestion to the total volume available.

As used herein, the term “pitch” refers to the distance between rows ofrepeated congestion obstacles. Pitch is oftentimes measured as amultiple of the average congestion diameter (i.e., 8D=8 diameterlengths).

As used herein, the term “risk” refers to the probability and theconsequence of an accidental event.

As used herein, the term “azeotropic mixture” refers to a mixture madeup of two or more refrigerants with similar boiling points that acts asa single fluid. The components of an azeotropic mixture typically do notseparate under normal operating conditions and can be charged as a vaporor liquid.

As used herein, the term “near-azeotropic mixture” refers to a mixturemade up of two or more refrigerants with different boiling points that,when in a totally liquid or vapor state, act as one component. However,when changing from vapor to liquid or liquid to vapor, the individualrefrigerants evaporate or condense at different temperatures.

As used herein, the term “derivative” refers to a compound that isderived from a similar compound.

In closing, it should be noted that the discussion of any reference isnot an admission that it is prior art to the present invention,especially any reference that may have a publication date after thepriority date of this application. At the same time, each and everyclaim below is hereby incorporated into this detailed description orspecification as a additional embodiments of the present invention.

Although the systems and processes described herein have been describedin detail, it should be understood that various changes, substitutions,and alterations can be made without departing from the spirit and scopeof the invention as defined by the following claims. Those skilled inthe art may be able to study the preferred embodiments and identifyother ways to practice the invention that are not exactly as describedherein. It is the intent of the inventors that variations andequivalents of the invention are within the scope of the claims whilethe description, abstract and drawings are not to be used to limit thescope of the invention. The invention is specifically intended to be asbroad as the claims below and their equivalents.

REFERENCES

All of the references cited herein are expressly incorporated byreference. The discussion of any reference is not an admission that itis prior art to the present invention, especially any reference that mayhave a publication data after the priority date of this application.Incorporated references are listed again here for convenience:

-   1. U.S. Pat. No. 7,849,691-   2. US 20100122551-   3. US 20100281915

1. A method for liquefaction of natural gas comprising: a) cooling anatural gas stream via indirect heat exchange with a first nonflammablerefrigerant selected from the group consisting of: difluoromethane,pentafluoromethane, trifluoromethane, hexafluoroethane,tetrafluoroethane, pentafluorethane, trifluoroethane, pentafluoroethane,any derivative thereof, and any combination thereof during a firstrefrigeration cycle; and b) cooling the natural gas stream via indirectheat exchange with a second refrigerant during a second refrigerationcycle.
 2. The method of claim 1 wherein the first refrigerant or thesecond refrigerant includes a hydrocarbon component in an amount rangingfrom about 0.1% to about 99% by volume.
 3. The method of claim 2 whereinthe hydrocarbon is selected from the group consisting of: ethylene,propane, and any combination thereof.
 4. The method of claim 1 whereinthe first refrigerant or the second refrigerant is an azeotropic mixtureor a near-azeotropic mixture.
 5. The method of claim 1 wherein the firstrefrigerant is selected from a group consisting of: a 1:1 mixture ofdifluoromethane and pentafluoromethane; pentafluoroethane; a mixture oftrifluoroethane, pentafluoroethane and tetrafluoroethane; and anyderivative thereof.
 6. The method of claim 1 wherein the secondrefrigerant is a nonflammable refrigerant comprising a mixture oftrifluoromethane and hexafluoroethane.
 7. The method of claim 1, furthercomprising: c) producing liquefied natural gas.
 8. The method of claim7, further comprising: d) vaporizing the liquefied natural gas.
 9. Amethod for liquefaction of natural gas comprising: a) providing at leastone nonflammable refrigerant selected from the group consisting of:difluoromethane, pentafluoroethane, trifluoromethane, hexafluoroethane,tetrafluoroethane, pentafluorethane, trifluoroethane, pentafluoroethane,any derivative thereof, and any combination thereof; and b) cooling anatural gas stream in an LNG facility via indirect heat exchange withthe nonflammable refrigerant.
 10. The method of claim 9 wherein the LNGfacility is located offshore.
 11. The method of claim 9 wherein therefrigerant includes a hydrocarbon component in an amount ranging fromabout 0.1% to about 99% by volume.
 12. The method of claim 11 whereinthe hydrocarbon is selected from the group consisting of: ethylene,propane, and any combination thereof.
 13. The method of claim 9 whereinat least three nonflammable refrigerants are used to cool the naturalgas stream and produce liquefied natural gas.
 14. The method of claim 13wherein the liquefied natural gas is vaporized.
 15. The method of claim9 wherein a first nonflammable refrigerant is used to cool the naturalgas stream in a closed-loop refrigeration cycle and second nonflammablerefrigerant is used to cool the natural gas stream in an open-looprefrigeration cycle.
 16. The method of claim 9 wherein the refrigerantis an azeotropic or near-azeotropic mixture.
 17. A method forliquefaction of natural gas comprising: a) cooling a natural gas streamin a LNG facility via indirect heat exchange with a first nonflammablerefrigerant selected from the group consisting of: difluoromethane,pentafluoroethane, trifluoromethane, hexafluoroethane,tetrafluoroethane, pentafluorethane, trifluoroethane, pentafluoroethane,any derivative thereof, and any combination thereof during a firstrefrigeration cycle; b) cooling the natural gas stream in the LNGfacility via indirect heat exchange with a second refrigerant during asecond refrigeration cycle; and c) cooling the natural gas stream in theLNG facility via indirect heat exchange with a third refrigerant duringthe third refrigeration cycle.
 18. The method of claim 17 wherein thefirst refrigerant is selected from a group consisting of: a 1:1 mixtureof difluoromethane and pentafluoromethane; pentafluoroethane; a mixtureof trifluoroethane, pentafluoroethane and tetrafluoroethane; and anyderivative thereof.
 19. The method of claim 17 wherein the secondrefrigerant is a mixture of trifluoromethane and hexafluoroethane. 20.The method of claim 17 wherein the third refrigerant is methane.
 21. Themethod of claim 17 wherein the first refrigerant or the secondrefrigerant includes a hydrocarbon component in an amount ranging fromabout 0.1% to about 99% by volume.
 22. The method of claim 21 whereinthe hydrocarbon is selected from the group consisting of: ethylene,propane, and any combination thereof.
 23. The method of claim 17 whereinthe LNG facility is located offshore.
 24. The method of claim 17,further comprising: d) producing liquefied natural gas.
 25. The methodof claim 24, further comprising: e) vaporizing the liquefied naturalgas.